Rich-Gas Condensate Huff and Puff Process in High-Volume, Watered-Out, and Highly Viscous Heavy Oil Wells, Case Study in Iraq

2021 ◽  
Author(s):  
Xueqing Tang ◽  
Ruifeng Wang ◽  
Zhongliang Cheng ◽  
Hui Lu
Keyword(s):  
High Pressure ◽  
Heavy Oil ◽  
Oil Quality ◽  
Oil Wells ◽  
Gas Condensate ◽  
Oil Viscosity ◽  
Foamy Oil ◽  
Artificial Lift ◽  
Water Coning ◽  
The Dead

Abstract Halfaya field in Iraq contains multiple vertically stacked oil and gas accumulations. The major oil horizons at depth of over 10,000 ft are under primary development. The main technical challenges include downdip heavy oil wells (as low as 14.56 °API) became watered-out and ceased flow due to depleted formation pressure. Heavy crude, with surface viscosities of above 10,000 cp, was too viscous to lift inefficiently. The operator applied high-pressure rich-gas/condensate to re-pressurize the dead wells and resumed production. The technical highlights are below: Laboratory studies confirmed that after condensate (45-52ºAPI) mixed with heavy oil, blended oil viscosity can cut by up to 90%; foamy oil formed to ease its flow to the surface during huff-n-puff process.In-situ gas/condensate injection and gas/condensate-lift can be applied in oil wells penetrating both upper high-pressure rich-gas/condensate zones and lower oil zones. High-pressure gas/condensate injected the oil zone, soaked, and then oil flowed from the annulus to allow large-volume well stream flow with minimal pressure drop. Gas/condensate from upper zones can lift the well stream, without additional artificial lift installation.Injection pressure and gas/condensate rate were optimized through optimal perforation interval and shot density to develop more condensate, e.g. initial condensate rate of 1,000 BOPD, for dilution of heavy oil.For multilateral wells, with several drain holes placed toward the bottom of producing interval, operating under gravity drainage or water coning, if longer injection and soaking process (e.g., 2 to 4 weeks), is adopted to broaden the diluted zone in heavy oil horizon, then additional recovery under better gravity-stabilized vertical (downward) drive and limited water coning can be achieved. Field data illustrate that this process can revive the dead wells, well production achieved approximately 3,000 BOPD under flowing wellhead pressure of 800 to 900 psig, with oil gain of over 3-fold compared with previous oil rate; water cut reduction from 30% to zero; better blended oil quality handled to medium crude; and saving artificial-lift cost. This process may be widely applied in the similar hydrocarbon reservoirs as a cost-effective technology in Middle East.

Experimental Study and Modeling of Heating Effect in Electrical Submersible Pump Operating With Ultra-Heavy Oil

2018 ◽  
Author(s):  
Jorge Luiz Biazussi ◽  
Cristhian Porcel Estrada ◽  
William Monte Verde ◽  
Antonio Carlos Bannwart ◽  
Valdir Estevam ◽  
...  
Keyword(s):  
Heavy Oil ◽  
Critical Factor ◽  
High Viscosity ◽  
Inlet Temperature ◽  
Outlet Temperature ◽  
Heating Effect ◽  
Submersible Pump ◽  
Oil Viscosity ◽  
Artificial Lift ◽  
Electrical Submersible Pump

A notable trend in the realm of oil production in harsh environments is the increasing use of Electrical Submersible Pump (ESP) systems. ESPs have even been used as an artificial-lift method for extracting high-viscosity oils in deep offshore fields. As a way of reducing workover costs, an ESP system may be installed at the well bottom or on the seabed. A critical factor, however, in deep-water production is the low temperature at the seabed. In fact, these low temperatures constitute the main source for many flow-assurance problems, such as the increase in friction losses due to high viscosity. Oil viscosity impacts pump performance, reducing the head and increasing the shaft power. This study investigates the influence of a temperature increase of ultra-heavy oil on ESP performance and the heating effect through a 10-stage ESP. Using several flow rates, tests are performed at four rotational speeds and with four viscosity levels. At each rotational speed curve, researchers keep constant the inlet temperature and viscosity. The study compares the resulting data with a simple heat model developed to estimate the oil outlet temperature as functions of ESP performance parameters. The experimental data is represented by a one-dimensional model that also simulates a 100-stage ESP. The simulations demonstrate that as the oil heat flows through the pump, the pump’s efficiency increases.

Experimental Analysis of the Effects of Varying Temperature and Viscosities on Foamy Oil Production

2021 ◽  
Author(s):  
Jasmine Shivani Medina ◽  
Iomi Dhanielle Medina ◽  
Gao Zhang
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Elevated Temperatures ◽  
Oil Production ◽  
Oil Reservoirs ◽  
Oil Viscosity ◽  
Gas Recovery ◽  
Foamy Oil ◽  
Heavy Oil Reservoirs ◽  
Pressure Depletion

Abstract The phenomenon of higher than expected production rates and recovery factors in heavy oil reservoirs captured the term "foamy oil," by researchers. This is mainly due to the bubble filled chocolate mousse appearance found at wellheads where this phenomenon occurs. Foamy oil flow is barely understood up to this day. Understanding why this unusual occurrence exists can aid in the transfer of principles to low recovery heavy oil reservoirs globally. This study focused mainly on how varying the viscosity and temperature via pressure depletion lab tests affected the performance of foamy oil production. Six different lab-scaled experiments were conducted, four with varying temperatures and two with varying viscosities. All experiments were conducted using lab-scaled sand pack pressure depletion tests with the same initial gas oil ratio (GOR). The first series of experiments with varying temperatures showed that the oil recovery was inversely proportional to elevated temperatures, however there was a directly proportional relationship between gas recovery and elevation in temperature. A unique observation was also made, during late-stage production, foamy oil recovery reappeared with temperatures in the 45-55°C range. With respect to the viscosities, a non-linear relationship existed, however there was an optimal region in which the live-oil viscosity and foamy oil production seem to be harmonious.

scholarly journals Gas Pressure Cycling (GPC) and Solvent-Assisted Gas Pressure Cycling (SA-GPC) Enhanced Oil Recovery Processes in a Thin Heavy Oil Reservoir

Energies ◽  
2020 ◽  
Vol 13 (19) ◽  
pp. 5047
Author(s):  
Olusegun Ojumoola ◽  
Hongze Ma ◽  
Yongan Gu
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Gas Pressure ◽  
Oil Viscosity ◽  
Step Size ◽  
Foamy Oil ◽  
Pressure Cycling ◽  
Eor Processes ◽  
Solvent Trapping

In this paper, gas pressure cycling (GPC) and solvent-assisted gas pressure cycling (SA-GPC) were developed as two new and effective enhanced oil recovery (EOR) processes. Eight coreflood tests were conducted by using a 2-D rectangular sandpacked physical model with a one or two-well configuration. More specifically, two cyclic solvent injection (CSI), three GPC, and three SA-GPC tests were conducted after the primary production, whose pressure was declined in steps from Pi = 3.0 MPa to Pf = 0.2 MPa. It was found that the CSI tests had poor performances because of the known CSI technical shortcomings and an additional technical issue of solvent trapping found in this study. Quick heavy oil viscosity regainment resulted in the solvent-trapping zone. In contrast, C3H8-GPC test at a pressure depletion step size of ∆PEOR = 0.5 MPa and C3H8-SA-CO2-GPC test at ∆PEOR = 1.0 MPa had the highest total heavy oil recovery factors (RFs) of 41.9% and 36.6% of the original oil-in-place (OOIP) among the two respective series of GPC and SA-GPC tests. The better performances of these two tests than C3H8- or CO2-CSI test were attributed to the effective displacement of the foamy oil toward the producer in the two-well configuration. Thus the back-and-forth movements of the foamy oil in CSI test in the one-well configuration were eliminated in these GPC and SA-GPC tests. Furthermore, C3H8-GPC test outperformed C3H8-SA-CO2-GPC test in terms of the heavy oil RF and cumulative gas-oil ratio (cGOR) because of the formation of stronger foamy-oil flow and the absence of CO2, which reduced the solubility of C3H8 in the heavy oil in the latter test. In summary, different solvent-based EOR processes were ranked based on the heavy oil RFs as follows: C3H8-GPC > C3H8-SA-CO2-GPC > CO2-GPC > C3H8-CSI > CO2-CSI.

Performance Analysis of the Artificial Lift Systems for Heavy Oil Wells in the Egyptian Eastern Desert

2019 ◽  
Author(s):  
Mahmoud Atef El Gharbawi ◽  
Ahmed Ahemd Elgibaly ◽  
Adel Mohamed Salem ◽  
Mohamed Abbas
Keyword(s):  
Performance Analysis ◽  
Heavy Oil ◽  
Eastern Desert ◽  
Oil Wells ◽  
Artificial Lift

Study on Preparation of Water-Soluble DRA for High Water Heavy Oil Well and Field Application Evaluation

2012 ◽  
Vol 616-618 ◽  
pp. 680-684
Author(s):  
Zheng Jun Long ◽  
Ya Rong Fu ◽  
Dong Qing Li ◽  
Li Xia Fu ◽  
Qian Fu
Keyword(s):  
Drag Reduction ◽  
Heavy Oil ◽  
High Water ◽  
Oil Wells ◽  
Water Soluble ◽  
Viscosity Reduction ◽  
High Water Content ◽  
Oil Well ◽  
Production Plant ◽  
Oil Viscosity

The high water content of heavy oil emulsions are O / W or W / O unstable estate, to solve the problem of heavy oil wells in the viscosity, after a large number of laboratory tests, a water-soluble drag reduction agent(DRA) with excellent drag reducing effect for high water heavy oil well is developed. The water-soluble DRA does not have combustible nature and solves also the problem of the security risk commonly used lower flash point viscosity reducing agent in paraffin oil well. The formulations and preparation method of the water-soluble drag reduction agent are introduced and the field applications are evaluated in this paper. The applications of more than 110 oil wells in Fifth Oil Production Plant in North China Oilfield have shown that the heavy oil viscosity reduction and drag reduction effects of water-soluble DRA are remarkable, and the hot wash cycle of oil well is prolonged.

New Method Combines Simulation and Novel Spreadsheet Tools to Enable Direct Optimization of Expansion Decisions in a Giant Heavy-Oil Field

2007 ◽  
Vol 10 (01) ◽  
pp. 35-42 ◽  
Author(s):  
W. Terry Osterloh ◽  
Wendell P. Menard
Keyword(s):  
Heavy Oil ◽  
Interpolation Method ◽  
Oil Quality ◽  
Main Tool ◽  
Horizontal Wells ◽  
Oil Field ◽  
Oil Viscosity ◽  
Direct Optimization ◽  
Oil Accumulation ◽  
Full Field

Summary Giant, geologically complex heavy-oil fields can take decades to develop, so development decisions made early in the life of the field can have long-range implications. Decision and risk analysis (D&RA) is often needed to make decisions that will maximize the risk-adjusted economic benefit. Unfortunately, in large fields, D&RA can be very challenging because of the large number of variables and the endless number of development and expansion scenarios to analyze. The time needed to complete a D&RA can become prohibitive when full-field reservoir simulation is the main tool for forecasting primary production and well count, with one simulation taking many hours or days to complete. This paper describes two new methods developed to overcome these challenges for a specific depletion-drive heavy-oil reservoir: a method for optimally populating a model with hundreds of horizontal wells, and a method to optimize expansion decisions quickly and directly. The utility of these tools has not been determined for other reservoirs and/or recovery mechanisms. A semiautomated spreadsheet-and-simulation method was developed to quickly place and select hundreds to thousands of hypothetical/future horizontal wells in a multimillion-gridblock model. Because the method automatically accounted for all model static properties and their effects on dynamic production response, the hypothetical wells had productivity characteristics very similar to the actual drilled wells placed in the model. A multivariate nonlinear interpolation method was developed that enabled full-field forecasts—for any combination of acreage allocation, well count, drilling order, and field rate constraint—to be calculated in less than 5 seconds, compared to approximately 20 hours for traditional simulation. Extensive validation work showed that well count and production curves from the spreadsheet virtually overlaid those obtained using traditional simulation of the particular expansion scenario. Such close agreement was possible because the basis of the spreadsheet forecast was utilization of traditional simulation forecasts from a handful of relevant cases. A key breakthrough beyond just fast forecasting was the coupling of the following three components inside the same spreadsheet: the fast forecasting method, calculation of an economic indicator/objective function (NPV), and commercial optimization tools. This linkage made possible, perhaps for the first time (at least at this scale), realization of direct optimization of any development scenario in a matter of minutes to a few hours, depending on the number of variables being optimized. Introduction The field in question was a giant extra heavy-oil accumulation covering hundreds of square miles and containing billions of barrels of 7 to 9ºAPI gravity oil trapped in shallow (1,500 to 3,000 ft) sandstone reservoirs of Miocene age (Fig. 1). The major reservoir sands were deposited in fluvial and fluviotidal channel systems. Reservoir properties were excellent, with porosity values of up to 36% and permeability values of up to 30-40 darcies. The gross interval was divided into three independent reservoir intervals by thick shales and further subdivided into a total of 12 sands. The variations in depth and oil gravity resulted in variations in pressure, temperature, solution gas/oil ratio (GOR), and oil viscosity (in-situ live-oil viscosity ranged from 1,000 to 10,000 cp). An upgrader was built to partially refine the crude. The upgrader capacity limited maximum production rate, and the contract term limited the production duration; combined, these defined the maximum that could be produced under the project scope. Whether this maximum would be achieved was contingent on drilling sufficient wells to fill the upgrader for the whole term. The ultimate number of wells required would depend on the performance of these wells, which in turn would depend on their locations, the reservoir and oil quality encountered, and the operating constraints imposed by artificial lift methods, pipeline pressures, and facility capacities.

Studies on the Stability of the Foamy Oil in Developing Heavy Oil Reservoirs

2017 ◽  
Vol 371 ◽  
pp. 111-116 ◽  
Author(s):  
Bashir Busahmin ◽  
Brij Maini ◽  
Rama Rao Karri ◽  
Maziyar Sabet
Keyword(s):  
High Pressure ◽  
Foam Stability ◽  
Oil Stability ◽  
Gas Content ◽  
Dissolved Gas ◽  
Oil Viscosity ◽  
High Pressure Cell ◽  
Daily Production ◽  
Foamy Oil ◽  
The Stability

In the process of natural energy depletion, foamy oil is characterized of low production Gas Oil Ratio, high oil viscosity, high daily production rate and high primary recovery factor. The stability of the foam turns out to be the prevailing factor that governs the life of the ‘foamy oil’. To enumerate the main factors affecting the stability of the foam, a high-temperature–high-pressure visualized experiment model for foamy oil stability test was developed. A serial of experiments was conducted to evaluate the performance of the foam stability. The effects of oil viscosity, height of the oil column, dissolved gas content and dispersed gas were investigated and recorded. These experiments were conducted using a Hele-Shaw, a high pressure cell. The volume of foamy oil produced, either by a step reduction in pressure or by a gradual (linear) reduction in pressure, and its subsequent decay was observed, visually. The experimental results show that foamy oil stability increases with higher oil viscosity, higher oil column, higher dissolved gas content and higher pressure decline rate. Asphaltene content was not observed to increase the foamy oil stability significantly. The results also show that the foam quality of foamy oils is much lower than aqueous foams.

Novel Techniques for Measuring Heavy-Oil Fluid Properties

SPE Journal ◽  
2007 ◽  
Vol 12 (03) ◽  
pp. 305-315 ◽  
Author(s):  
Nina Naireka Goodarzi ◽  
Jonathan Luke Bryan ◽  
An Thuy Mai ◽  
Apostolos Kantzas
Keyword(s):  
Heavy Oil ◽  
Ct Scanning ◽  
Oil Reservoirs ◽  
Oil Viscosity ◽  
Free Gas ◽  
Foamy Oil ◽  
Heavy Oil Reservoirs ◽  
Fluid Properties ◽  
Oil Density

Summary Investigating the properties of live heavy oil, as pressure declines from the original reservoir pressure to ambient pressure, can aid in interpreting and simulating the response of heavy-oil reservoirs undergoing primary production. Foamy oil has a distinctly different and more complex behavior compared to conventional oil as the reservoir pressure depletes and the gas leaves solution from the oil. Solution gas separates very slowly from the oil; thus, conventional pressure/volume/temperature (PVT) measurements are not trivial to perform. In this paper, we present novel experiments that utilize X-ray computerized assisted technology (CT) scanning and low field nuclear magnetic resonance (NMR) techniques. These nondestructive tomographic methods are capable of providing unique in-situ measurements of how oil properties change as pressure depletes in a PVT cell. Specifically, this paper details measurements of oil density, oil and gas formation volume factor, solution gas/oil ratio, (GOR), and oil viscosity as a function of pressure. Experiments were initially performed at a slow rate, as in conventional PVT tests, allowing equilibrium to be reached at each pressure step. These results are compared to non-equilibrium tests, whereby pressure declines linearly with time, as in coreflood experiments. The incremental benefit of the proposed techniques is that they provide more detailed information about the oil, which improves our understanding of foamy-oil properties. Introduction Understanding fluid behavior of heavy oils is important for reservoir simulation and production response predictions. In heavy-oil reservoirs, the oil viscosity and density are commonly reported, but there is little experimental data in the literature reporting how oil properties change with pressure. This information would be especially useful for production companies seeking to understand and improve their primary (cold production) response. It is already widely known that foamy-oil behavior is a major cause for increased production in cold heavy-oil reservoirs along with sand production. Therefore, it would be valuable to first study the bulk fluid properties of live heavy oil prior to sandpack-depletion experiments. If the response of these properties to incremental pressure reduction can be established, this can be compared with fluid expansion during pressure depletion in a sandpack. CT scanning is useful in studying high-pressure PVT relationships. Images of a pressure vessel filled with live oil can be taken as the volume of the vessel is expanded and used to calculate bulk densities and free gas saturation. Also, CT images allow us to visually see where free gas is formed in the vessel. For example, CT scanning can be used to provide an indication of whether or not small bubbles nucleate within the oil and then slowly coalesce into a gas cap, or if free gas forms straight away. CT scanning provides much more information than conventional PVT cells. Uncertainties about where gas is forming in the oil, its effect on oil properties, and transient behavior cannot be reconciled in conventional PVT cells. Also, from CT images, the formation of microbubbles could be inferred based on the density of the oil with the dissolved gas. If the oil density decreases below the bubblepoint pressure, then it is likely that gas has come out of solution but remains within the oil; therefore, the resulting mixture is less dense than the original live oil. However, if oil density increases as the gas evolves, then the oil does not contain small gas bubbles, and gas has separated from the oil. Also, the free gas saturation growth with time, and comparison of images at equilibrium vs. immediately after the expansion of the vessel, can provide mass transfer information about gas bubble growth, supersaturation, and gravity separation. When characterizing heavy oil and bitumen fluid properties, oil viscosity is one of the most important pieces of information that has to be obtained. The high viscosities of heavy oil and bitumen present a significant obstacle to the technical and economic success of a given enhanced oil recovery option. As a result, in-situ oil viscosity measurement techniques would be of considerable benefit to the industry. In heavy-oil reservoirs that are undergoing primary production, this problem is further complicated by the presence of the gas leaving solution with the oil. Above the bubblepoint, the gas is fully dissolved into the oil; thus, the live oil exists as a single-phase fluid. Once the pressure drops below the bubblepoint and gas begins to leave solution, the oil viscosity behavior is no longer well understood. In addition to our CT analysis, this work also presents the use of low field NMR as a tool for making in-situ viscosity estimates of live and foamy oil. NMR spectra change significantly as pressure drops and gas leaves solution, and these changes can be correlated to physical changes in the oil viscosity.

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